Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54417 

Dated: August 14, 2013. 

Sandra Henriquez, 

Assistant Secretary for Public and Indian 

Housing. 

[FR Doc. 2013–21610 Filed 9–3–13; 8:45 am] 

BILLING CODE 4210–67–P 

DEPARTMENT OF THE INTERIOR 

Bureau of Safety and Environmental 

Enforcement 

30 CFR Part 250 

[Docket ID: BSEE–2012–0005; 13XE1700DX 

EX1SF0000.DAQ000 EEEE500000] 

RIN 1014–AA10 

Oil and Gas and Sulphur Operations 

on the Outer Continental Shelf—Oil 

and Gas Production Safety Systems 

Correction 

In proposed rule document 2013– 

19861, appearing on pages 52240 

through 52284 in the issue of Thursday, 

August 22, 2013, make the following 

corrections: 

1. On pages 52241 through 52242, the 

table should read as follows: 

Current regulation Proposed rule 

§ 250.800 General requirements ............................................................ § 250.800 General. 

250.801 Subsurface safety devices ....................................................... § 250.810 Dry tree subsurface safety devices—general. 

§ 250.811 Specifications for subsurface safety valves (SSSVs)—dry 

trees. 

§ 250.812 Surface-controlled SSSVs—dry trees. 

§ 250.813 Subsurface-controlled SSSVs. 

§ 250.814 Design, installation, and operation of SSSVs—dry trees. 

§ 250.815 Subsurface safety devices in shut-in wells—dry trees. 

§ 250.816 Subsurface safety devices in injection wells—dry trees. 

§ 250.817 Temporary removal of subsurface safety devices for routine 

operations. 

§ 250.818 Additional safety equipment—dry trees. 

§ 250.821 Emergency action. 

§ 250.825 Subsea tree subsurface safety devices—general. 

§ 250.826 Specifications for SSSVs—subsea trees. 

§ 250.827 Surface-controlled SSSVs—subsea trees. 

§ 250.828 Design, installation, and operation of SSSVs—subsea 

trees. 

§ 250.829 Subsurface safety devices in shut-in wells—subsea trees. 

§ 250.830 Subsurface safety devices in injection wells—subsea trees. 

§ 250.832 Additional safety equipment—subsea trees. 

§ 250.837 Emergency action and safety system shutdown. 

§ 250.802 Design, installation, and operation of surface productionsafety systems.§ 250.819 Specification for surface safety valves (SSVs). 

§ 250.820 Use of SSVs. 

§ 250.833 Specification for underwater safety valves (USVs). 

§ 250.834 Use of USVs. 

§ 250.840 Design, installation, and maintenance—general. 

§ 250.841 Platforms. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
54418 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

Current regulation Proposed rule 

§ 250.842 Approval of safety systems design and installation features. 

§ 250.803 Additional production system requirements .......................... § 250.850 Production system requirements—general. 

§ 250.851 Pressure vessels (including heat exchangers) and fired 

vessels. 

§ 250.852 Flowlines/Headers. 

§ 250.853 Safety sensors. 

§ 250.855 Emergency shutdown (ESD) system. 

§ 250.856 Engines. 

§ 250.857 Glycol dehydration units. 

§ 250.858 Gas compressors. 

§ 250.859 Firefighting systems. 

§ 250.862 Fire and gas-detection systems. 

§ 250.863 Electrical equipment. 

§ 250.864 Erosion. 

§ 250.869 General platform operations. 

§ 250.871 Welding and burning practices and procedures. 

§ 250.804 Production safety-system testing and records ...................... § 250.880 Production safety system testing. 

§ 250.890 Records. 

§ 250.805 Safety device training ............................................................ § 250.891 Safety device training. 

§ 250.806 Safety and pollution prevention equipment quality assurance requirements.§ 250.801 Safety and pollution prevention equipment (SPPE) certification. 

§ 250.802 Requirements for SPPE. 

§ 250.807 Additional requirements for subsurface safety valves and 

related equipment installed in high pressure high temperature 

(HPHT) environments.

§ 250.804 Additional requirements for subsurface safety valves 

(SSSVs) and related equipment installed in high pressure high temperature (HPHT) environments. 

§ 250.808 Hydrogen sulfide ................................................................... § 250.805 Hydrogen sulfide. 

New Sections § 250.803 What SPPE failure reporting procedures must I follow? 

§ 250.831 Alteration or disconnection of subsea pipeline or umbilical. 

§ 250.835 Specification for all boarding shut down valves (BSDV) associated with subsea systems. 

§ 250.836 Use of BSDVs. 

§ 250.838 What are the maximum allowable valve closure times and 

hydraulic bleeding requirements for an electro-hydraulic control system? 

§ 250.839 What are the maximum allowable valve closure times and 

hydraulic bleeding requirements for a direct-hydraulic control system? 

§ 250.854 Floating production units equipped with turrets and turret 

mounted systems. 

§ 250.860 Chemical firefighting system. 

§ 250.861 Foam firefighting system. 

§ 250.865 Surface pumps. 

§ 250.866 Personal safety equipment. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54419 

Current regulation Proposed rule 

§ 250.867 Temporary quarters and temporary equipment. 

§ 250.868 Non-metallic piping. 

§ 250.870 Time delays on pressure safety low (PSL) sensors. 

§ 250.872 Atmospheric vessels. 

§ 250.873 Subsea gas lift requirements. 

§ 250.874 Subsea water injection systems. 

§ 250.875 Subsea pump systems. 

§ 250.876 Fired and Exhaust Heated Components. 

2. On page 52251, the table should 

read as follows: 

3. On page 52254, Table 2 should read 

as follows: 


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54420 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

4. On pages 52256 through 52260, the 

table should read as follows: 


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Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54421 


tkelley on DSK3SPTVN1PROD with PROPOSALSEP04SE13.003</GPH>

I Citation 30 Hou' ~ AvmgeNo. Annual 

CFR 250, Reporting and Recordkeeping B d of Annual Burden 

I Subpart A Requirement ur en Responses Hours 

I 1 

NEW: Demonstrate to us that by using 2 

BAST the benefits are insufficient to justifY 5 I justifications 10 

the cost. 

Subtotal 2 responses 10 hours 

I Citation I Average No. Annual Hour 

30 CFR250 Reporting and Recordkeeping Burden of Annual Burden 

Subpart H Requirement Responses Hours 

and NTL(s) Non-Hour Cost Burdens* I 

General Requirements 

800(a) Requirements for your production safety Burden included with 0 

system application. specific requirements 

I below. 

! 800(a); Prior to production, request approval of pre- 1 76 requests 76 

880(a); production inspection; notifY BSEE 72 hours 

before commencement so we may witness 

preproduction test and conduct ins}Jection. 

801(c) Request evaluation and approval [OORP] of 2 1 request 2 

other quality assurance programs covering 

manufacture of SPPE. 

802(c)(1 ); NEW: Submit statement/certification for: Not considered IC under 5 0 

852(e)(4); exposure functionality; pipe is suitable and CFR 1320.3(h)(1). 

861(b); manufacturer has complied with IVA; 

suitable fire fighting foam per original 

manufacturer specifications. 

802(c)(5) NEW: Document all manufacturing, 2 I 30 60 

traceability, quality control, and inspection documents 

requirements. Retain required documentation 

until 1 year after the date of decommissioning 

the e~me!1t. 

803(a) NEW: Within 30 days of discovery and 2 10 reports 20 

identification ofSPPE failure, provide a 

I 

written report of equipment failure to 

manufacturer. 

I 803(b) NEW: Document and determine the results 5 10 50 

I of I the SPPE failure within 60-days and documents ! I I corrective action taken. 

803(c) NEW: Submit [OORP] modified 2 I submittal 2 

procedures you made if notified by 

manufacturer of design changes or you 

changed operating or repair procedures as 

result of a failure, within 30 days. 

I 804 Submit detailed info regarding installing Burdens are covered under 0 

SSVs in an HPHT environment with your 30 CFR 250, Subparts D 

APD, APM, DWOP etc. and B, 1014-0018 and 

1014-0024. 

804(b); NEW: District Manager will approve on a Not considered IC per 5 0 i 

829(b), (c); case-by-case basis. CFR 1320.3(h)(6). I 

841(b); ! 
54422 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 


tkelley on DSK3SPTVN1PROD with PROPOSALSEP04SE13.004</GPH>

i 

I 

810; 816; 

825(a); 830; 

I 814(a); 821; 

I

i 828(a); 

I 838( c )(3); 

I 859(b); 

1 870(b); 

rsI7(b); 

i 869(a); 

I 

817(b) 

817(c) 

825(b); 831; 

833; 

837(c)(5); 

838( c); 

874(g)(2); 

874(f); 

Subtotal I 128 

i responses 

Surface and Subsurface Safety Systems - Dry Trees 

Submit request for a determination that a 5 % 41 wells 

well is incapable of natural flow'~ ____ = ______ --+ ____ '--____ 1 

VerifY the no-flow condition of the well y,. 

annually. 

Specific alternate approval requests requiring 

approval. 

IdentifY well with sign on wellhead that subsurface safety device is removed; flag safety 

devices that are out of service; a visual 

indicator must be used to identify the 

bypassed safety device. 

Record removal of subsurface safety device. 

1 Request alternate approval of master valve 

I [required to be submitted with an APM]. 

Subsea and Subsurface Safety 

NEW: NotifY BSEE: (1) if you cannot test 

all valves and sensors; (2) 48 hours in 

advance if monitoring ability affected; (3) 

designating USV2 or another qualified 

valve; (4) resuming production; (5) 12 hours 

of detecting loss of communication; 

immediately if you cannot meet value 

closure conditions. 

Burden covered under 30 

CFR 250, subpart A, 1014-

0022. 

Usual/customary safety 

procedure for removing or 

identifYing out-of-service 

safety devices. 

Burden included in 

§ 250.890 of this subpart. 

Burden covered under 30 

CFR 250, subpart D, 1014-

0018. 

Subtotall 41 responses 

Subsea Trees 

(4) Y2 

(5) Y2 1 

i 827 NEW: Request remote location approval. I I request 

2 1 submittal 

210 hours 

246 

o 

o 

o 

o 

246 hours 

7 

1 

2 

Y2 10 requests 5 

1 831 NEW: Submit a repair/replacement plan to 

I - 1 monitor andtest. _____ -+-________ +-_____ +-________ ---I 

I 837(a) jl NEW: Request approval to not shut-in a 

2 1 submittal 2 

L_______ subseawell~anem~genc~ ____ ~----~--~---~~-~~~~-~--~ : 837(b) NEW: Prepare and submit for approval a 

I plan to shut-in wells affected by a dropped 

1 _________________ ollject. --

Y2 2 approvals 1 

2 2 4 

verifications 

2 1 approval 2 

I 837(c)(2) II NEW: Obtain approval to resume 

I pr~ducti~!1~ P/!-_ PSgL_s_e_n __ s0-c-r_. _____ j--___ -+ ___ _ 

I 838(a); I NEW: VerifY closure time of US V upon 

I 839(a)(2); I request of District Manager. 

i 838(c)~EW: Request approval to produce after 

! .,-/ I i~ss of communication; include alternate 

i I valve closure table. 

Subtotal 28 responses 24 hours 

Production Safety Systems i---84-2-;----r-jS-U-b-m-it-a-p-p--li-ca-t-io-n-, -and all - - r---1-6----rI-I-ap-p-h-' c-at-io-n---rl-------1-6-----

required/supporting information, for a $5,030 per submission x 1 = $5,030 

I production safety system with> 125 $13,238 per offshore visit x 1 = $13,238 

components. $6,884 per shipyard visit x 1 = $6,884 

25 - 125 components. 13 10 130 

applications 
Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54423 


tkelley on DSK3SPTVN1PROD with PROPOSALSEP04SE13.005</GPH>

i I 

I 

I 

[2500:,"G 

I Submit modification to application for r pmduction safety system whh > 125 

cOl11P.c>nents. 

25 125 components. 

< 25 components. 

842(b) NEW: Your application must also include 

certification(s) that the designs for 

mechanical and electrical systems were 

reviewed, approved, and stamped by 

registered professional engineer. [NOTE: 

Upon promulgation, these certification 

production safety systems requirements will 

I be consolidated into the application hour 

burden for the specific cO!!l£.().nents:J 

842(c) NEW: Submit a certification letter that the 

mechanical and electrical systems were 

installed in accordance with approved 

designs. 

842( d), (e); NEW: Submit a certification letter within 

60-days after production that the as-built 

diagrams, piping, and instrumentation 

diagrams are on file, certified correct, and 

stamped by a registered professional 

engineer; submit all the as-built diagrams. 

842(1) ] NEW: Maintain records pertaining to 

approved design and installation features and 

as-built pipe and instrumentation diagrams at 

your offshore field office or location 

available to the District Manager; make 

available to BSEE upon request and retained 

for the life of the facility. 

Add' Itlona , I P d ro uctlOn S system R 

851(a)(4) NEW: Request approval to use uncoded 

pressure and fired vessels beyond their 18 

months of continued use. 

I 851(b); Maintain [most current] pressure-recorder 

852(a)(3); information at location available to the 

858( c); District Manager for as long as information 

865(b); is valid. 

851(c)(2) NEW: Request approval from District 

Manager for activation limits set less than 5 

$1,218 per submission x 10= $12,180 I 

$8,313 per offshore visit x 1 = $8,313 I $4,766 per, shipyard visit x 1 = $4,766 I 

I 8 

I 

20 160 I 

applications I 

$6~4=r~~X2~L! 

I modifications .. .. .1 

~~"~ l"" SUbmiSSi;~J-18T~,¥o,,~1 

modifications I ·1 $201 ~ission x 758.1 $152,35~ 

5 I 329 1,645 I 

modifications I 

$85 per submission x 329 = $27,965 I 

6 

6 I 

I 

I 

I 

6 

;,s 

;,s 

Subtotal 

eqmrements 

2 

23 I 

I 

I 

1 

I 

32 192 

certifications 

32 letters 192 

32 letters 208 

32 records 16 

1,426 9,485 I 

I _JesI~ons~s_._ hours I -----_._---- ·-1 

$343,794 non-hour cost 

burdens 

1 request 2 

615 records 14,145 

10 requests 10 I 

I 
54424 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 


tkelley on DSK3SPTVN1PROD with PROPOSALSEP04SE13.006</GPH>

i ! psi. 

i 852(c)(l) I NEW: Request approval from District 1 10 requests 10 

~ _______ +_ Manager to vent to some other location. -+---------------1---------1--------1 

i 852(c)(2) I NEW: Request a different sized PSV. 1 1 request 5 

,----------------1------------------------------·-----------------------------. -----1----------------+-----------------------+--------------------1 

! 852(c)(2) i NEW: Request dIfferent upstream locatIOn 1 5 request 5 

! I of the PSV. 

852( e) Submit required design documentation for Burden is covered by the o 

unbonded flexible pipe. application requirement in 

r-----c-------+---~--c---~---:------c-~------c--------~--§~2--5-10-5·-8-42~T-------:c-:----~------~~--1 855(b) Maintain ESD schematic listing control 615 listings 9,225 

function of all safety devices at location 

conveniently available to the District 

!--____ +-M_anager for the life of_t_h_ec-f:a __ c_i_lity-,,-,. ____ !--___ ___+-----_+------I 

i 858(b) NEW: Request approval from District 1 Ii 1 request 1 II 

I Manager to use different procedure for gas- , 

i well gas affected. 

859(a)(2) Request approval for alternate firefighting 

system. 

Burden covered under 30 o 

CFR 250, subpart A, 

1014-0022. ~----------------------- --+------------------------------------------------------------------------------------1--"-------------- '-.-------+---------------------1 

859(a)(3), Post diagram of fire fighting system; furnish 5 38 postings 190 

i (4) evidence firefighting system suitable for 

II-I -=-=-::-:::-:--__ +-:'o~p<e-=ra:o:t,=-io-cl1~i~ su!>geezi~!illl=a::c:t-=es=-:·_;:__--_+_:=____:_--J---:-__:-------+-------1 I 859(b) NEW: Request extension from District Burden covered under 30 0 

I

I Manager up to 7 days of your approved CFR 250, subpart A, 1014-

departure to use chemicals. 0022. ---~~-~~c-~--~~~---+--c~-_,~~---___+--~---+ 

860(a); Request approval, including but not limited 22 31 requests 682 

related to, submittal of justification and risk 

NTL(s) assessment, to use chemical only fire 

prevention and control system in lieu of a 

water system. 

860(b) 

I 860(b) 

NEW: Minor change(s) made after approval 

rec'd re 860(a) - document change; maintain 

the revised version at facility or closest field 

office for BSEE review/inspection; maintain 

for life offaciiity. 

I NEW: Major change(s) made after approval 

I rec'd re 860(a) - submit new request 

w/updated risk assessment to District 

Manager for approval; maintain at facility or 

closest field office for BSEE 

review/inspection; maintain for life of 

facility. 

'is 10 minor 

changes 

2 1 major 

change 

, 861(b) 

I 

NEW: Submit foam concentrate samples 2 500 

annually to manufacturer for testing. submittals 

5 

2 

1,000 

: 864 Maintain erosion control program records for 12 615 records 7,380 

~ ______ ~;ce~yq~Uea~ers~st.~;:mc-a-k-e--a--va-i-la-b--I-_e __ tco~~B--S--E~E~U~-p-o~-n----4---~--+_~-----+_-~--~ , 867(a) NEW: Request approval from District 6 1 request 6 

1-1 ~---c ___ !--M_a~er to install te~rary qua_rt_er_s_. __ ---+ ____ ___+--------+------+ 

I 867(b) NEW: Submit supporting 1 I request 1 

information/documentation if required by I I District Manager to install a temporary 

~i _____ +-fi_lr_e_w_a_t_e_~s_t_e_m_. ___ ~ ______ _+----~-----_+-____ ~ 

867(c) NEW: Request approval fonn District 

manager to use temporary equipment for 

300 requests 300 
Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54425 

BILLING CODE 1505–01–C 

5. On page 52271, the table should 

read as follows: 

You must submit: Details and/or additional requirements: 

(1) A schematic piping and instrumentation diagram ............................... Showing the following: 

(i) Well shut-in tubing pressure; 

(ii) Piping specification breaks, piping sizes; 

(iii) Pressure relief valve set points; 

(iv) Size, capacity, and design working pressures of separators, flare 

scrubbers, heat exchangers, treaters, storage tanks, compressors 

and metering devices; 


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54426 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

You must submit: Details and/or additional requirements: 

(v) Size, capacity, design working pressures, and maximum discharge 

pressure of hydrocarbon-handling pumps; 

(vi) size, capacity, and design working pressures of hydrocarbon-handling vessels, and chemical injection systems handling a material 

having a flash point below 100 degrees Fahrenheit for a Class I 

flammable liquid as described in API RP 500 and 505 (both incorporated by reference as specified in § 250.198). 

(vii) Size and maximum allowable working pressures as determined in 

accordance with API RP 14E, Recommended Practice for Design 

and Installation of Offshore Production Platform Piping Systems (incorporated by reference as specified in § 250.198). 

(2) A safety analysis flow diagram (API RP 14C, Appendix E) and the 

related Safety Analysis Function Evaluation (SAFE) chart (API RP 

14C, subsection 4.3.3) (incorporated by reference as specified in 

§ 250.198).

if processing components are used, other than those for which Safety 

Analysis Checklists are included in API RP 14C, you must use the 

same analysis technique and documentation to determine the effects 

and requirements of these components upon the safety system. 

(3) Electrical system information, including .............................................. (i) A plan for each platform deck and outlining all classified areas. You 

must classify areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2; or 

API RP 505, Recommended Practice for Classification of Locations 

for Electrical Installations at Petroleum Facilities Classified as Class 

I, Zone 0, Zone 1, and Zone 2 (both incorporated by reference as 

specified in § 250.198). 

(ii) Identification of all areas where potential ignition sources, including 

non-electrical ignition sources, are to be installed showing: 

(A) All major production equipment, wells, and other significant hydrocarbon sources, and a description of the type of decking, ceiling, 

and walls (e.g., grating or solid) and firewalls and; 

(B) the location of generators, control rooms, panel boards, major 

cabling/conduit routes, and identification of the primary wiring method 

(e.g., type cable, conduit, wire) and; 

(iii) one-line electrical drawings of all electrical systems including the 

safety shutdown system. You must also include a functional legend. 

(4) Schematics of the fire and gas-detection systems ............................. showing a functional block diagram of the detection system, including 

the electrical power supply and also including the type, location, and 

number of detection sensors; the type and kind of alarms, including 

emergency equipment to be activated; the method used for detection; and the method and frequency of calibration. 

(5) The service fee listed in § 250.125. .................................................... The fee you must pay will be determined by the number of components involved in the review and approval process. 

6. On page 52272, the table should 

read as follows: 

Item name Applicable codes and requirements 

(1) Pressure and fired vessels where the operating pressure is or will 

be 15 pounds per square inch gauge (psig) or greater.

(i) Must be designed, fabricated, and code stamped according to applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler 

and Pressure Vessel Code. 

(ii) Must be repaired, maintained, and inspected in accordance with 

API 510, Pressure Vessel Inspection Code: In-Service Inspection, 

Rating, Repair, and Alteration, Downstream Segment (incorporated 

by reference as specified in § 250.198). 

(2) Pressure and fired vessels (such as flare and vent scrubbers) 

where the operating pressure is or will be at least 5 psig and less 

than 15 psig.

Must employ a safety analysis checklist in the design of each component. These vessels do not need to be ASME Code stamped as 

pressure vessels. 

(3) Pressure and fired vessels where the operating pressure is or will 

be less than 5 psig.

Are not subject to the requirements of paragraphs (a)(1) and (a)(2). 

(4) Existing uncoded Pressure and fired vessels (i) in use on the effective date of the final rule; (ii) with an operating pressure of 5 psig or 

greater; and (iii) that are not code stamped in accordance with the 

ANSI/ASME Boiler and Pressure Vessel Code.

Must be justified and approval obtained from the District Manager for 

their continued use beyond 18 months from the effective date of the 

final rule. 


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Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54427 

Item name Applicable codes and requirements 

(5) Pressure relief valves .......................................................................... (i) Must be designed and installed according to applicable provisions of 

sections I, IV, and VIII of the ASME Boiler and Pressure Vessel 

Code. 

(ii) Must conform to the valve sizing and pressure-relieving requirements specified in these documents, but (except for completely redundant relief valves), must be set no higher than the maximum-allowable working pressure of the vessel. 

(iii) And vents must be positioned in such a way as to prevent fluid 

from striking personnel or ignition sources. 

(6) Steam generators operating at less than 15 psig ............................... Must be equipped with a level safety low (LSL) sensor which will shut 

off the fuel supply when the water level drops below the minimum 

safe level. 

(7) Steam generators operating at 15 psig or greater .............................. (i) Must be equipped with a level safety low (LSL) sensor which will 

shut off the fuel supply when the water level drops below the minimum safe level. 

(ii) You must also install a water-feeding device that will automatically 

control the water level except when closed loop systems are used 

for steam generation. 

7. On pages 52275 through 52276, the 

table should read as follows: 

For the use of a chemical firefighting system on major and minor 

manned platforms, you must provide the following in your risk assessment . . . Including . . . 

(i) Platform description .............................................................................. (A) The type and quantity of hydrocarbons (i.e., natural gas, oil) that 

are produced, handled, stored, or processed at the facility. 

(B) The capacity of any tanks on the facility that you use to store either 

liquid hydrocarbons or other flammable liquids. 

(C) The total volume of flammable liquids (other than produced hydrocarbons) stored on the facility in containers other than bulk storage 

tanks. Include flammable liquids stored in paint lockers, storerooms, 

and drums. 

(D) If the facility is manned, provide the maximum number of personnel on board and the anticipated length of their stay. 

(E) If the facility is unmanned, provide the number of days per week 

the facility will be visited, the average length of time spent on the facility per day, the mode of transportation, and whether or not transportation will be available at the facility while personnel are on 

board. 

(F) A diagram that depicts: quarters location, production equipment location, fire prevention and control equipment location, lifesaving appliances and equipment location, and evacuation plan escape routes 

from quarters and all manned working spaces to primary evacuation 

equipment. 

(ii) Hazard assessment (facility specific) .................................................. (A) Identification of all likely fire initiation scenarios (including those resulting from maintenance and repair activities). For each scenario, 

discuss its potential severity and identify the ignition and fuel 

sources. 

(B) Estimates of the fire/radiant heat exposure that personnel could be 

subjected to. Show how you have considered designated muster 

areas and evacuation routes near fuel sources and have verified 

proper flare boom sizing for radiant heat exposure. 

(iii) Human factors assessment (not facility specific) ............................... (A) Descriptions of the fire-related training your employees and contractors have received. Include details on the length of training, 

whether the training was hands-on or classroom, the training frequency, and the topics covered during the training. 

(B) Descriptions of the training your employees and contractors have 

received in fire prevention, control of ignition sources, and control of 

fuel sources when the facility is occupied. 

(C) Descriptions of the instructions and procedures you have given to 

your employees and contractors on the actions they should take if a 

fire occurs. Include those instructions and procedures specific to 

evacuation. State how you convey this information to your employees and contractor on the platform. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
54428 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

For the use of a chemical firefighting system on major and minor 

manned platforms, you must provide the following in your risk assessment . . . Including . . . 

(iv) Evacuation assessment (facility specific) ........................................... (A) A general discussion of your evacuation plan. Identify your muster 

areas (if applicable), both the primary and secondary evacuation 

routes, and the means of evacuation for both. 

(B) Description of the type, quantity, and location of lifesaving appliances available on the facility. Show how you have ensured that lifesaving appliances are located in the near vicinity of the escape 

routes. 

(C) Description of the types and availability of support vessels, whether 

the support vessels are equipped with a fire monitor, and the time 

needed for support vessels to arrive at the facility. 

(D) Estimates of the worst case time needed for personnel to evacuate 

the facility should a fire occur. 

(v) Alternative protection assessment ...................................................... (A) Discussion of the reasons you are proposing to use an alternative 

fire prevention and control system. 

(B) Lists of the specific standards used to design the system, locate 

the equipment, and operate the equipment/system. 

(C) Description of the proposed alternative fire prevention and control 

system/equipment. Provide details on the type, size, number, and location of the prevention and control equipment. 

(D) Description of the testing, inspection, and maintenance program 

you will use to maintain the fire prevention and control equipment in 

an operable condition. Provide specifics regarding the type of inspection, the personnel who conduct the inspections, the inspection 

procedures, and documentation and recordkeeping. 

(vi) Conclusion .......................................................................................... A summary of your technical evaluation showing that the alternative 

system provides an equivalent level of personnel protection for the 

specific hazards located on the facility. 

8. On pages 52279 through 52280, the 

table spanning those two pages should 

read as follows: 

If your 

subsea gas 

lift system introduces the 

lift gas to the 

. . . 

Then you must install a . . . 

Additional requirements 

API Spec 6A and API Spec 

6AV1 (both incorporated by 

reference as specified in 

§ 250.198) gas-lift shutdown valve (GLSDV), and 

. . . 

FSV on the 

gas-lift supply pipeline 

. . . 

PSHL on the 

gas-lift supply . . . 

API Spec 6A 

and API Spec 

6AV1 manual 

isolation 

valve . . . 

(1) Subsea 

Pipelines, 

Pipeline Risers, or 

Manifolds 

via an External Gas 

Lift Pipeline.

meet all of the requirements 

for the BSDV described in 

250.835 and 250.836 on 

the gas-lift supply pipeline. 

upstream (in 

board) of 

the GLSDV 

pipeline upstream (in 

board) of 

the GLSDV 

downstream 

(out board) 

of the PSHL 

and above 

the waterline. This 

valve does 

not have to 

be actuated. 

(i) Ensure that the MAOP of a subsea gas 

lift supply pipeline is equal to the MAOP 

of the production pipeline. an actuated 

fail-safe close gas-lift isolation valve 

(GLIV) located at the point of intersection 

between the gas lift supply pipeline and 

the production pipeline, pipeline riser, or 

manifold. (ii) Install an actuated fail-safe 

close gas-lift isolation valve (GLIV) located at the point of intersection between 

the gas lift supply pipeline and the production pipeline, pipeline riser, or manifold. Install the GLIV downstream of the 

underwater safety valve(s) (USV) and/or 

AIV(s). 


tkelley on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54429 

If your 

subsea gas 

lift system introduces the 

lift gas to the 

. . . 

Then you must install a . . . 

Additional requirements 

API Spec 6A and API Spec 

6AV1 (both incorporated by 

reference as specified in 

§ 250.198) gas-lift shutdown valve (GLSDV), and 

. . . 

FSV on the 

gas-lift supply pipeline 

. . . 

PSHL on the 

gas-lift supply . . . 

API Spec 6A 

and API Spec 

6AV1 manual 

isolation 

valve . . . 

(2) Subsea 

Well(s) 

through the 

Casing 

String via an 

External 

Gas Lift 

Pipeline. 

Locate the GLSDV within 10 

feet of the first of access to 

the gas-lift riser or topsides 

umbilical termination assembly (TUTA) (i.e., within 

10 feet of the edge of the 

platform if the GLSDV is 

horizontal, or within 10 feet 

above the first accessible 

working deck, excluding 

the boat landing and above 

the splash zone, if the 

GLSDV is in the vertical 

run of a riser, or within 10 

feet of the TUTA if using 

an umbilical). 

on the platform upstream (in 

board) of 

the GLSDV 

pipeline on the 

platform 

downstream 

(out board) 

of the 

GLSDV. 

downstream 

(out board) 

of the PSHL 

and above 

the waterline. This 

valve does 

not have to 

be actuated. 

Install an actuated, fail-safe-closed GLIV on 

the gas lift supply pipeline near the wellhead to provide the dual function of containing annular pressure and shutting off 

the gas lift supply gas. If your subsea 

trees or tubing head is equipped with an 

annulus master valve (AMV) or an annulus wing valve (AWV), one of these may 

be designated as the GLIV. Consider installing the GLIV external to the subsea 

tree to facilitate repair and or replacement 

if necessary. 

(3) Pipeline 

Risers via a 

Gas-Lift 

Line Contained within 

the Pipeline 

Riser 

locate the GLSDV within 10 

feet of the first of access to 

the gas-lift riser or TUTA 

(i.e., within 10 feet of the 

edge of the platform if the 

GLSDV is horizontal, or 

within 10 feet above the 

first accessible working 

deck, excluding the boat 

landing and above the 

splash zone, if the GLSDV 

is in the vertical run of a 

riser, or within 10 feet of 

the TUTA if using an umbilical). 

upstream (in 

board) of 

the GLSDV 

flowline upstream (in 

board) of 

the FSV. 

downstream 

(out board) 

of the 

GLSDV. 

(i) Ensure that the gas-lift supply flowline 

from the gas-lift compressor to the 

GLSDV is pressure-rated for the MAOP of 

the pipeline riser. Ensure that any surface 

equipment associated with the gas-lift 

system is rated for the MAOP of the pipeline riser. (ii) Ensure that the gas-lift compressor discharge pressure never exceeds the MAOP of the pipeline riser. (iii) 

Suspend and seal the gas-lift flowline 

contained within the production riser in a 

flanged API Spec. 6A component such as 

an API Spec. 6A tubing head and tubing 

hanger or a component designed, constructed, tested, and installed to the requirements of API Spec. 6A. Ensure that 

all potential leak paths upstream or near 

the production riser BSDV on the platform 

provide the same level of safety and environmental protection as the production 

riser BSDV. In addition, ensure that this 

complete assembly is fire-rated for 30 

minutes. Attach the GLSDV by flanged 

connection directly to the API Spec. 6A 

component used to suspend and seal the 

gas-lift line contained within the production riser. To facilitate the repair or replacement of the GLSDV or production 

riser BSDV, you may install a manual isolation valve between the GLSDV and the 

API Spec. 6A component used to suspend and seal the gas-lift line contained 

within the production riser, or outboard of 

the production riser BSDV and inboard of 

the API Spec. 6A component used to 

suspend and seal the gas-lift line contained within the production riser. 

9. On page 52280, the second table 

should read as follows: 

Type of gas lift system Valve Allowable 

leakage rate 

Testing 

frequency 

(i) Gas Lifting a subsea pipeline, pipeline riser, or manifold via an external gas lift pipeline.GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
54430 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

Type of gas lift system Valve Allowable 

leakage rate 

Testing 

frequency 

GLIV .... N/A .................................................... Function tested quarterly, not to exceed 120 days. 

(ii) Gas Lifting a subsea well through the casing string 

via an external gas lift pipeline.

GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks. 

GLIV .... 400 cc per minute of liquid or 15 scf 

per minute of gas.

Function tested quarterly, not to exceed 120 days. 

(iii) Gas lifting the pipeline riser via a gas lift line contained within the pipeline riser.GLSDV Zero leakage. .................................... Monthly, not to exceed 6 weeks. 

10. On page 52281, the table should 

read as follows: 

Valve Allowable leakage rate Testing frequency 

(i) WISDV ........................................................... Zero leakage .................................................... Monthly, not to exceed 6 weeks. 

(ii) Surface-controlled SSSV or WIV .................. 400 cc per minute of liquid or ..........................

15 scf per minute of gas ..................................

Semiannually, not to exceed 

6 calendar months. 

11. On page 52282, the first table 

should read as follows: 

Item name Testing frequency, allowable leakage rates, and other requirements 

(i) Surface-controlled SSSVs (including devices 

installed in shut-in and injection wells).

Not to exceed 6 months. Also test in place when first installed or reinstalled. If the device does 

not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas 

leakage rate > 15 cubic feet per minute is observed, the device must be removed, repaired, 

and reinstalled or replaced. Testing must be according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) to ensure proper operation. 

(ii) Subsurface-controlled SSSVs ....................... Not to exceed 6 months for valves not installed in a landing nipple and 12 months for valves 

installed in a landing nipple. The valve must be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced. 

(iii) Tubing plug ................................................... Not to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 

400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the plug must be removed, repaired, and reinstalled, or replaced. An additional tubing plug may be installed in lieu of removal. 

(iv) Injection valves ............................................. Not to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 

400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the valve must be removed, repaired and reinstalled, or replaced. 

12. On page 52282, the second table 

should read as follows: 

Item name Testing frequency and requirements 

(i) PSVs ............................................................... Once each 12 months, not to exceed 13 months between tests. Valve must either be benchtested or equipped to permit testing with an external pressure source. Weighted disc vent 

valves used as PSVs on atmospheric tanks may be disassembled and inspected in lieu of 

function testing. 

(ii) Automatic inlet SDVs that are actuated by a 

sensor on a vessel or compressor.

Once each calendar month, not to exceed 6 weeks between tests. 

(iii) SDVs in liquid discharge lines and actuated 

by vessel low-level sensors.

Once each calendar month, not to exceed 6 weeks between tests. 

(iv) SSVs ............................................................. Once each calendar month, not to exceed 6 weeks between tests. Valves must be tested for 

both operation and leakage. You must test according to API RP 14H (incorporated by reference as specified in § 250.198). If an SSV does not operate properly or if any fluid flow is 

observed during the leakage test, the valve must be immediately repaired or replaced. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 54431 

Item name Testing frequency and requirements 

(v) FSVs .............................................................. Once each calendar month, not to exceed 6 weeks between tests. All FSVs must be tested, 

including those installed on a host facility in lieu of being installed at a satellite well. You 

must test FSVs for leakage in accordance with the test procedure specified in API RP 14C, 

appendix D, section D4, table D2 subsection D (incorporated by reference as specified in 

§ 250.198). If leakage measured exceeds a liquid flow of 400 cubic centimeters per minute 

or a gas flow of 15 cubic feet per minute, the FSV must be repaired or replaced. 

13. On page 52283, the first table 

should read as follows: 

Item name Testing frequency and requirements 

(i) Pumps for firewater systems .......................... Must be inspected and operated according to API RP 14G, Section 7.2 (incorporated by reference as specified in § 250.198). 

(ii) Fire- (flame, heat, or smoke) detection systems.Must be tested for operation and recalibrated every 3 months provided that testing can be performed in a non-destructive manner. Open flame or devices operating at temperatures that 

could ignite a methane-air mixture must not be used. All combustible gas-detection systems 

must be calibrated every 3 months. 

(iii) ESD systems. ............................................... (A) Pneumatic based ESD systems must be tested for operation at least once each calendar 

month, not to exceed 6 weeks between tests. You must conduct the test by alternating ESD 

stations monthly to close at least one wellhead SSV and verify a surface-controlled SSSV 

closure for that well as indicated by control circuitry actuation. 

(B) Electronic based ESD systems must be tested for operation at least once every three calendar months, not to exceed 120 days between tests. The test must be conducted by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled 

SSSV closure for that well as indicated by control circuitry actuation. 

(C) Electronic/pneumatic based ESD systems must be tested for operation at least once every 

three calendar months, not to exceed 120 days between tests. The test must be conducted 

by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation. 

(iv) TSH devices ................................................. Must be tested for operation at least once every 12 months, excluding those addressed in 

paragraph (b)(3)(v) of this section and those that would be destroyed by testing. Those that 

could be destroyed by testing must be visually inspected and the circuit tested for operations at least once every 12 months. 

(v) TSH shutdown controls installed on compressor installations that can be nondestructively tested.Must be tested every 6 months and repaired or replaced as necessary. 

(vi) Burner safety low .......................................... Must be tested at least once every 12 months. 

(vii) Flow safety low devices ............................... Must be tested at least once every 12 months. 

(viii) Flame, spark, and detonation arrestors ...... Must be visually inspected at least once every 12 months. 

(ix) Electronic pressure transmitters and level 

sensors: PSH and PSL; LSH and LSL.

Must be tested at least once every 3 months, but no more than 120 days elapse between 

tests. 

(x) Pneumatic/electronic switch PSH and PSL; 

pneumatic/electronic switch/electric analog 

with mechanical linkage LSH and LSL controls.

Must be tested at least once each calendar month, but with no more than 6 weeks elapsed 

time between tests. 

14. On page 52283, the second table 

should read as follows: 

Item name Testing frequency, allowable leakage rates, and other requirements 

(i) Surface-controlled SSSVs (including 

devices installed in shut-in and injection wells).

Tested semiannually, not to exceed 6 months. If the device does not operate properly, or if a liquid 

leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute 

is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be 

according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) 

to ensure proper operation, or as approved in your DWOP. 


tkelley on DSK3SPTVN1PROD with PROPOSALS
54432 Federal Register / Vol. 78, No. 171 / Wednesday, September 4, 2013 / Proposed Rules 

Item name Testing frequency, allowable leakage rates, and other requirements 

(ii) USVs .................................................. Tested quarterly, not to exceed 120 days. If the device does not function properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is 

observed, the valve must be removed, repaired and reinstalled, or replaced. 

(iii) BSDVs ............................................... Tested monthly, not to exceed 6 weeks. Valves must be tested for both operation and leakage. You 

must test according to API RP 14H for SSVs (incorporated by reference as specified in § 250.198). 

If a BSDV does not operate properly or if any fluid flow is observed during the leakage test, the 

valve must be immediately repaired or replaced. 

(iv) Electronic ESD logic .......................... Tested monthly, not to exceed 6 weeks. 

(v) Electronic ESD function ..................... Tested quarterly, not to exceed 120 days. Shut-in at least one well during the ESD function test. If 

multiple wells are tied back to the same platform, a different well should be shut-in with each quarterly test. 

[FR Doc. C1–2013–19861 Filed 9–3–13; 8:45 am] 

BILLING CODE 1505–01–D 

DEPARTMENT OF HEALTH AND 

HUMAN SERVICES 

42 CFR Part 84 

[Docket No. CDC–2013–0017; NIOSH–250] 

Development of Inward Leakage 

Standards for Half-Mask Air-Purifying 

Particulate Respirators 

AGENCY: Centers for Disease Control and 

Prevention, HHS. 

ACTION: Request for comment and notice 

of public meeting. 

SUMMARY: The National Institute for 

Occupational Safety and Health 

(NIOSH) of the Centers for Disease 

Control and Prevention (CDC) 

announces a public meeting concerning 

inward leakage performance 

requirements for the class of NIOSHcertified non-powered air-purifying 

particulate respirators approved as halffacepiece respirators for protection from 

particulate-only hazards. The purpose of 

this meeting is to share information and 

to seek stakeholder feedback, in 

identified topic areas, concerning the 

development of inward leakage 

performance standards. Questions 

concerning the identified topics of 

specific interest are included in this 

document. Attendance at the public 

meeting is not required to submit 

written responses to the questions in 

this notice. 

DATES: The public meeting will be held 

September 17, 2013, 1:00 p.m.–5:00 

p.m. ET, or after the last public 

commenter has spoken. Stakeholder 

comments to the questions included in 

this document must be received by 

11:59 p.m. ET on October 18, 2013. 

ADDRESSES: Meeting location: Bruceton 

Research Center, NIOSH National 

Personal Protective Technology 

Laboratory (NPPTL), 626 Cochrans Mill 

Road, Building 140, Multi-purpose 

Room, Pittsburgh, PA 15236. This 

meeting will also be available by remote 

access. 

Written Comments: You may submit 

comments by either of the following 

methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the 

instructions for submitting comments. 

• Mail: NIOSH Docket Office, Robert 

A. Taft Laboratories, MS–C34, 4676 

Columbia Parkway, Cincinnati, OH 

45226. 

Instructions: All submissions received 

must include the agency name (Centers 

for Disease Control and Prevention, 

HHS) and docket number (CDC–2013– 

0017; NIOSH–250). All relevant 

comments, including any personal 

information provided, will be posted 

without change to http://

www.regulations.gov. 

Docket: For access to the docket to 

read background documents and 

submitted comments, go to http://

www.regulations.gov. 

FOR FURTHER INFORMATION CONTACT: 

Colleen Miller, NIOSH National 

Personal Protective Technology 

Laboratory (NPPTL), 626 Cochrans Mill 

Road, Pittsburgh, PA 15236 (412) 386– 

4956 or (412) 386–5200 (these are not 

toll free numbers). 

SUPPLEMENTARY INFORMATION: 

I. Background 

Testing, quality control, and other 

requirements under 42 CFR Part 84 are 

intended to ensure that respirators 

supplied to U.S. workers provide 

effective protection when properly 

employed within a complete respiratory 

protection program, as specified under 

MSHA and OSHA regulations. NIOSH 

requirements governing approval of 

half-mask air-purifying particulate 

respirators, those defined in this notice, 

are principally specified in Part 84, 

under Subpart K—Non-Powered AirPurifying Particulate Respirators. The 

performance of the respirator’s 

facepiece-to-face seal and other 

potential sources of inward leakage for 

this type of respirator are important to 

determine how much unfiltered 

contaminated air the worker might 

inhale. The facepiece-to-face seal 

leakage can be substantial in the case of 

a poorly fitting respirator. Effective fit 

testing technology and procedures exist 

to ensure that half-mask respirators 

approved by NIOSH under Subpart K of 

Part 84 have adequately performing 

facepiece-to-face seals. The purpose of 

this notice is to solicit stakeholder 

feedback regarding standards for inward 

leakage testing. 

NIOSH believes that the employee is 

more likely to achieve a good fit from 

a respirator design that has been 

demonstrated to achieve a specified 

minimum level of performance during 

certification testing. Accordingly, 

NIOSH initiated rulemaking activities to 

establish inward leakage performance 

requirements for NIOSH-approved 

particulate filtering respirators by 

publishing a notice of proposed 

rulemaking (NPRM) in the Federal 

Register on October 30, 2009 [74 FR 

56141]. The public comment period for 

the rulemaking closed originally on 

December 28, 2009 but was 

subsequently extended upon request by 

stakeholders to September 30, 2010. 

Public meetings were held on December 

3, 2009 and July 29, 2010 to allow 

stakeholders to share feedback on the 

proposed rule, including preliminary 

results of their independently 

completed or ongoing research. NIOSH 

reviewed all comments submitted by 

stakeholders and is considering them in 

the development of a revised inward 

leakage standard. 

II. Test Panel History 

Although NIOSH requires adequate 

facepiece-to-face seals for other types of 

respirators under Part 84, such 

requirements have not been applied to 


tkelley on DSK3SPTVN1PROD with PROPOSALS